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ICR Development Schedule and Proposed Values for ARA Auctions 2020-2023

This presentation reviews the development schedule and proposed Installed Capacity Requirement (ICR) values for Annual Reconfiguration Auctions (ARAs) to be conducted from 2020 to 2023. It includes calculations, comparisons, and observations for the ICR-Related Values.

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ICR Development Schedule and Proposed Values for ARA Auctions 2020-2023

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  1. Power Supply Planning Committee September 9, 2019 | Teleconference Manasa Kotha Resource Studies and Assessments • 2020-2021 Third Annual Reconfiguration Auction (2020-2021 ARA 3) • 2021-2022 Second Annual Reconfiguration Auction (2021-2022 ARA 2) • 2022-2023 First Annual Reconfiguration Auction (2022-2023 ARA 1) Proposed Installed Capacity Requirement (ICR) Values Revision 1

  2. Objective of this Presentation • Review the ICR-Related Values* development schedule for the ARAs to be conducted in 2020 • Review the proposed ICR values for the ARAs to be conducted in 2020 Note: Please see Appendix II for the acronyms used in the presentation • * The ICR, net ICR, LRA, TSA, LSR, MCL, the Marginal Reliability Impact (MRI) system and zonal Demand Curves and the Hydro-Quebec Interconnection Capability Credits(HQICCs) are collectively referred to as the ICR-Related Values

  3. ARAs’ ICR-Related Values Development Schedule • ICR-Related Values for the following ARAs to be conducted in 2020 will be calculated, reviewed and filed concurrently: • 2020-2021 ARA 3 • 2021-2022 ARA 2 • 2022-2023 ARA 1

  4. Proposed ICR Values for CCP 2020-2021 ARA 3, CCP 2021-2022 ARA 2 and CCP 2022-2023 ARA 1 4

  5. ICR Calculation Details • Notes: • All values in the table are in MW except the reserve margin which is shown in percent • ALCC is the “Additional Load Carrying Capability” used to bring the system to the 0.1 days/year LOLE Reliability Criterion • APk is the forecast gross 50/50 peak load net of BTM PV

  6. Comparison of ICR-Related Values (MW)CCP ARAs Vs Corresponding CCP FCA Revision 1: new slide Notes: • For details on the calculation of the ICR-Related Values for FCA 11 through FCA 13, please see: https://www.iso-ne.com/static-assets/documents/2016/09/a2_2020_21_fca11_icr_values_results.pdf, https://www.iso-ne.com/static-assets/documents/2017/09/a7_icr_and_tie_benefits_for_fca12.zip, https://www.iso-ne.com/static-assets/documents/2018/09/a5_icr_fca_13_and_related_values.zip, respectively. • 50/50 peak load Net of BTM PV shown for informational purposes

  7. Observations Revision 1: new slide • The ARA ICRs for the 2020-2021 through 2022-2023 CCPs are lower than their respective FCA ICRs • The difference in ICR values increases as the CCP gets closer While the ISO did not simulate the exact effect of the assumption changes on the ARA ICRs as compared with their respective FCA ICRs, based on results of simulations conducted to identify the effect of updated assumptions on net ICR for FCA 14, one could conclude that similar directional effects are applicable to the ARA ICR simulations when compared with their respective FCA ICR simulations. The directional effect of updated assumptions on net ICR may be summarized as follows: • Improved resource performance (i.e. lower EFORd) decreases net ICR • Lower forecast loads decrease net ICR • Lower tie benefits increase net ICR (CCP 2020-2021 only) • Increase in minimum system reserve increases net ICR (CCPs 2020-2021 and 2021-2022) • Change in load relief assumed obtainable from 1.5% to 1.0 % of 90/10 net peak would increase net ICR

  8. Appendix I Assumptions for the CCP 2020-2021 ARA 3, CCP 2021-2022 ARA 2 and CCP 2022-2023 ARA 1 ICR-Related Values Calculations

  9. Modeling the New England Control Area for ARAs to be Conducted in 2020 • The General Electric Multi-Area Reliability Simulation model (GE MARS) is used to calculate several of the ICR-Related Values • Internal transmission constraints are not modeled in the ICR calculation. All loads and resources are assumed to be connected to a single electric bus • Internal transmission constraints are addressed through the LSR and MCLs • A LSR will be calculated for the import-constrained Southeast New England (SENE) Capacity Zone, consisting of the NEMA/Boston, SEMA, and RI Load Zones • A MCL will be calculated for the export-constrained Northern New England (NNE) Capacity Zone, consisting of the combined Load Zones of Maine, New Hampshire, and Vermont • The MRI based method for calculating demand curves will be used to develop System and Capacity Zone Demand Curves

  10. Assumptions for the ICR-Related Values Calculations • Load forecast • Net of behind-the-meter (BTM) photovoltaic (PV) resource forecast • Load forecast distribution • Qualified Capacity (QC) of resources* • Generating Capacity Resources • Intermittent Power Resources (IPR) • Import Capacity Resources • Demand Resources (DR) • Resource availability • Generating Resources’ availability • Intermittent Power Resources’ availability • Demand Resources’ availability * Known resource retirements are removed; new cleared capacity resources are added as applicable; capacity imports are de-rated according to assumed external transmission transfer capability .

  11. OP-4 Actions used to Develop Assumptions for the ICR-Related Values Calculations • Load or capacity relief are assumed to be obtainable from implementing the following actions of the Operating Procedure No. 4, Action during a Capacity Deficiency (OP-4) • Requests for emergency assistance from neighboring Control Areas (Tie reliability benefits) • Quebec (includes Hydro-Quebec Interconnection Capability Credits (HQICCs)) • Maritimes (New Brunswick) • New York • Initiation of 5% voltage reduction

  12. Load Forecast (MW)For Applicable Capacity Zones and Total New England • 50/50 & 90/10 reference (net of BTM PV) load forecasts values are from the 2019 CELT load forecast (labeled“2A Summer (MW): ISONE Control Area, New England States, RSP Sub-areas, and SMD Load Zones”) for the corresponding RSP sub-areas used in the ARA ICR Values calculations (see: https://www.iso-ne.com/static-assets/documents/2019/04/forecast_data_2019.xlsx) • The reference 50/50 load forecast shown is for informational purposes; in the ICR Valuescalculations, the GE MARS model sees an hourly distribution of loads with the BTM PV modeled with an hourly profile and a 7-day window uncertainty methodology • The 90/10 load forecast values are used directly in the calculation of TSA for import-constrained Capacity Zones; all other values shown are for informational purposes

  13. Load Forecast, cont.Modeling of BTM PV • ICR calculations will use an hourly profile of BTM PV corresponding to the load shape for the year 2002, used by the Northeast Power Coordinating Council (NPCC) for reliability studies. For more information on the development of the hourly profile see: https://www.iso-ne.com/static-assets/documents/2017/06/pspc_6_22_2017_2002_PV_profile.pdf • Used for all probabilistic ICR-Related Values calculations • Modeled in GE MARS by Regional System Plan (RSP) 13-subarea representation • Includes an 8% transmission and distribution gross-up • Peak load reduction uncertainty is modeled (randomly selected by MARS from a seven day window distribution) • The values of BTM PV published in the 2019 CELT Report are the values of BTM PV subtracted from the gross load forecast to determine the net load forecast • The published 90/10 net load forecast for the SENE sub-areas is used in the TSA Note: For more info on the PV forecast, see https://www.iso-ne.com/static-assets/documents/2019/04/final-2019-pv-forecast.pdf

  14. Resources’ Qualified Capacity (QC) Resource Data : Used the latest available data for each CCP • Import Capacity Resources • The QC values are de-rated if the sum of the import QC is higher than the remaining transmission transfer capability (TTC) of the external interface after accounting for tie benefits • This is the same procedure used for the ARA ICR calculations in previous years *Qualified New Capacity Resources on critical path schedule monitoring with deliverability prior to June 1, 2022

  15. Resources’ QC (MW)By Capacity Zone & Total New England 2020-2021 ARA 3 2021-2022 ARA 2 2022-2023 ARA 1 Notes: • Generating resources exclude a 30 MW derating to reflect the value of the firm Vermont Joint Owners (VJO) contract for CCP 2020-2021 and CCP 2021-2022 • Known retirement requests are removed from the applicable CCP

  16. Internal TTC Assumptions (MW)- For LSR and MCL Modeling • Note: • Based on transmission transfer capability limits presented at the March 20, 2019 Reliability Committee meeting. The presentation is available at: https://www.iso-ne.com/static-assets/documents/2019/03/a7_fca_14_transmission_transfer_capabilities_and_capacity_zone_development.pdf

  17. Resource Availability Assumptions Generating Capacity Resources • Forced outages assumption • Each generating unit’s Equivalent Forced Outage Rate on demand (non-weighted EFORd) modeled • Based on a 5-year average (Jan 2014 – Dec 2018) of generating unit data submitted to Generation Availability Data System (GADS) • NERC GADS Class average data is used for immature & non-commercial units • Scheduled outage assumption • Each generating unit’s weeks of maintenance modeled • Based on a 5-year average (Jan 2014 – Dec 2018) of each generating unit’s actual historical average of planned and maintenance outages scheduled at least 14 days in advance • NERC GADS class average data is used for immature & non-commercial units • Each CCP will have the appropriate generating units modeled along with their individual availability statistics • Intermittent Power Resources are modeled as 100% available since their outages have been incorporated in their 5-year historical output used in their ratings determination

  18. Resource Availability Assumptions, cont. Demand Resources (DR) • Use historical DR performance from summer & winter 2014 – 2018 (same values developed for FCA 14) For more information see the May 2019 PSPC presentation: https://www.iso-ne.com/static-assets/documents/2019/05/a3_dr_season_perfrmnce_0530219.pdf • Modeled by Load Zones and type of DR with outage factor calculated as 1- performance/100 • The same performance values will be applied for CCP 2020-2021 through CCP 2022-2023

  19. Resource Availability Assumptions, cont. Import Capacity Resources • Modeled in the ICR calculations as: • Pool backed are 100% available • Resource backed are modeled with availability assumptions shown below

  20. Resource Availability Assumptions, cont. CCP 2020-2021 ARA 3 • Notes: • Non-intermittent Generating Capacity Resources uses the same per unit EFORd and maintenance weeks values developed for FCA 14. In the LOLE simulations, individual unit values are modeled • Assumed summer MW weighted EFORd/Forced Outage Rate (FOR) and maintenance weeks are shown by resource types for informational purposes • Non-intermittent Generating Capacity Resources category excludes a 30 MW derating to reflect the value of the firm VJO contract

  21. Resource Availability Assumptions, cont. CCP 2021-2022 ARA 2 • Notes: • Non-intermittent Generating Capacity Resourcesuses the same per unit EFORd and maintenance weeks values developed for FCA 14. In the LOLE simulations, individual unit values are modeled • Assumed summer MW weighted EFORd/FOR and maintenance weeks are shown by resource type for informational purposes • Non-intermittent Generating Capacity Resources excludes a 30 MW derating to reflect the value of the firm VJO contract

  22. Resource Availability Assumptions, cont. CCP 2022-2023 ARA 1 • Notes: • Non-intermittent Generating Resources uses the same per unit EFORd and Maintenance weeks values developed for FCA 14. In the LOLE simulations, individual unit values are modeled • Assumed summer MW weighted EFORd/FOR and maintenance weeks are shown by resource types for informational purposes

  23. TSA Assumptions for Import Capacity Zone2020-2021 ARA 3, 2021-2022 ARA 2 and 2022-2023 ARA 1 2020-2021 ARA 3 2021-2022 ARA 2 2022-2023 ARA 1 • Notes: • DR Qualified Capacity are the same values as shown in Slide 15 • DR derating factors used in TSA are the same factors that are being used in FCA 14 ICR calculations • RI: 15%; SEMA:3%; NEMA:11% • Peaking Generating Capacity Resources use the individual unit’s availability (EFORd)

  24. Assumed Load Relief Obtainable from OP-4 Actions 6 & 8⁠ (implement 5% Voltage Reduction) (MW) • Uses the 90-10 Peak load forecast net of BTM PV minus all DR multiplied by the 1% value assumed in estimating relief obtained from OP-4 voltage reduction

  25. OP4 Assumptions, cont. - Tie Benefits • Values for 2020-2021 ARA 3 tie benefits are based on the results of the 2020-2021 ARA 3 tie benefits study. The results are available at: https://www.iso-ne.com/static-assets/documents/2019/08/20190809_pspc_tie_benefits_ara3_study_assumptions.pptx • Values for 2021-2022 ARA 2 and 2022-2023 ARA 1 are those calculated for the corresponding FCAs (FCA 12 and FCA 13, respectively) • The tie benefits availability assumptions will be based on the availability assumptions associated with the external transmission line updated using the newly proposed methodology* • These are the same values used to model the performance of the Import Capacity Resources that are pool-backed *Based on recently updated values using the newly proposed methodology presented at the March 30, 2019 Power Supply Planning Committee meeting. The presentation is available at:https://www.iso-ne.com/static-assets/documents/2019/05/a5_tie_line_availability_05302019.pdf

  26. OP4 Assumptions, cont. - Minimum System Reserve Assumption (MW) • Minimum system reserve is the minimum reserves held for transmission system security • Modeled at 700 MW

  27. Summary of all MW Modeled in the ICR Values Calculations Notes: • Generating Capacity Resources excludes a 30 MW de-rate to reflect the value of the firm VJO contract for CCP 2020-2021 and CCP 2021-2022 • Intermittent Power Resources have both the summer and winter capacity values modeled • Import Capacity Resources reflect a derating to account for TTC and each CCP’s tie benefits • OP-4 voltage reduction includes both Action 6 and Action 8 MW assumptions • Minimum system reserve is the minimum reserves held for transmission system security • Tie benefits for 2020-2021 are the results of the 2020-2021 ARA 3 tie benefits study; tie benefits for 2021-2022 and 2022-2023 are those calculated for the corresponding FCA

  28. Appendix II Acronyms

  29. Acronyms • ALCC – Additional Load Carrying Capability • APk – Gross peak load net of BTM PV • ARA – Annual Reconfiguration Auction • BTM PV – Behind-the-meter photovoltaic • FCA – Forward Capacity Auction • CCP – Capacity Commitment Period • CSO – Capacity Supply Obligation • CELT – Capacity, Energy, Loads and Transmission • CT – Connecticut • DR – Demand Resource • EE – Energy Efficiency • FCA – Forward Capacity Auction

  30. Acronyms, cont. • FERC – Federal Energy Regulatory Commission • PSPC – Power Supply Planning Committee • HQICCs – Hydro-Quebec Interconnection Capability Credits • ICR – Installed Capacity Requirement • ISO – ISO New England • LRA – Local Resource Adequacy • LSR – Local Sourcing Requirement • GE MARS – General Electric Multi-area Reliability Simulation • MCL – Maximum Capacity Limit • MRI – Marginal Reliability Impact • Net ICR – ICR minus HQICCs • OP-4 – Operating Procedure No. 4, Action During a Capacity Deficiency

  31. Acronyms, cont. • PC – Participants Committee • QC – Qualified Capacity • RSP – Regional System Plan • RC – Reliability Committee • SMD – Standard Market Design • TSA – Transmission Security Analysis

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